We’re getting a clearer picture of how renewable energy developers and advocacy organizations feel about proposed reforms to generator interconnection being considered by the Federal Energy Regulatory Commission (FERC).
FERC’s Notice of Proposed Rulemaking on generator interconnection stands to upend how energy projects are tied to the grid.
Here are some of the key takeaways from comments filed in response to the NOPR.
Commercial Readiness Requirements
There are 3 parts to the June 2022 FERC NOPR “Improvements to Generator Interconnection Procedures and Agreements.” Commercial readiness requirements are in Part A – Reforms to Implement a First-Ready, First-Served Cluster Study Process. After several rounds of comments in the past six months, on Dec. 16, FERC received the final set of industry comments. We can expect a final order on generator interconnection procedures sometime in early 2023.
FERC is trying to boost renewable projects ready to advance in the interconnection queue in this particular aspect of Part A. Along with increasing study deposits, tightening site control, and formalizing study withdrawal penalties, FERC believed existing interconnection requirements did not require interconnection customers to be commercially ready in the early stages of the study cycle. FERC wanted to reduce the number of “speculative” projects and the resulting re-studies with this requirement.
Several renewable developers (Pine Gate, Longroad Energy, Nextera Energy, Invenergy, and Engie North America) and associations (Solar Energy Industries Association and American Clean Power Association) are opposed to this requirement. They believe that “at-risk” readiness deposits (starting at $4,000/MW at MISO to enter the queue and then increase in later study phases) are sufficient. But MISO favors a non-refundable commercial readiness deposit to reduce the speculative projects in the queue.
FERC Commissioner Allison Clements joined the Factor This! podcast to discuss the agency’s interconnection reform efforts, grid-enhancing technologies, resiliency, and more. Subscribe wherever you get your podcasts.
Optional Interconnection Studies
In Part A, FERC also explored the idea of optional interconnection studies to provide more information to the developers before submitting their study requests. Again, the idea here was to reduce the studies in the queue. FERC proposed limiting to 5 studies at a time per interconnection customer in a cycle, and each study would require a $10,000 deposit.
SEIA, Longroad, Nextera Energy (“NEE”), and MISO oppose the concept of optional interconnection studies. Instead of these optional studies, SEIA proposed to FERC (Pine Gate Renewables, AES Clean Energy, and Pattern Energy also support) the following information should be provided to interconnection customers:
1. “Flowgate data, such as disconnect switches, breakers, transformers, conductors, series reactors, and ground clearances of lines;
2. Change file models of network upgrades for deliverability in advance of providing study results;
3. Base case models paired with contingencies, including local contingencies (below 200 kV);
4. Incremental injection capacity available at each bus in the transmission provider’s footprint under N-1 conditions with a five-year outlook;
5. The rating of the monitored facility; and
6. Proposed upgrades in the area that could affect interconnection requests.”
In the same section, FERC also pointed out MISO’s Points Of Interconnection (POI) map as an example of a heat map to help developers look for locations where network upgrade costs might be less than other locations. Only a large energy consumer, Google LLC, seems to favor that idea, with Longroad Energy opposing it. Google said there should be minimum requirements for transmission providers to post available information, including interactive heat maps. Longroad sees the value of hosting capacity maps in distribution planning but questions their benefit in transmission planning. Moreover, Longroad seems concerned about the real estate developers locking in large swaths of land if this information was available.
Penalties for Study Delays
In NOPR part B – Reforms to Increase the Speed of Interconnection Queue Processing, FERC had proposed a $500/day fine when studies are late after a 10-day grace period. MISO is vehemently opposed to this proposed requirement citing that one of its most frequent interconnection customers – NEE, is also opposed to these penalties. MISO says these penalties will result in “acrimony and distraction” and will not increase the speed of processing the interconnection queue.
But interconnection studies are routinely delayed. That’s a fact. According to MISO’s Definitive Planning Phase latest schedule, 34 projects submitted in the 2018 cycle in the MISO Central region are scheduled to see an interconnection agreement in April 2023, almost 5 years after entering the queue.
Imposing penalties on transmission providers like MISO sends the right signal to developers that FERC is fair to both developers and transmission providers. Because developers are taking the risk and tying up capital in their study deposits and milestone payments. SEIA favors penalties for delayed studies and suggests that FERC requires ISOs to recover these costs from transmission owners that failed to comply with study timelines.
Other takeaways – Affected Systems Studies and a new consumer protection coalition
Experienced developers such as NEE and Invenergy encouraged FERC to focus on Affected Systems Study reforms because they know from experience with MISO and SPP queue that it is a major source for study delay.
NEE implied in its comments that by applying a firm transmission service requirement (Network Resource Interconnection Service as opposed to less firm Energy Resource Interconnection Service), SPP is causing delays for its MISO projects. Invenergy mentioned an example with SPP’s interconnection queue, where one customer executed the interconnection agreement without the affected system study results. Due to these concerns, the American Clean Power Association is asking FERC to standardize Affected Systems Studies and require transmission providers such as MISO and SPP to include what type of service (ERIS or NRIS) is assumed for affected systems studies.
Lastly, a new coalition called the Interconnection Cost Consumer Protection Coalition, consisting of most renewable energy associations and developers like Enel North America and Engie North America, also submitted comments at FERC in this last round. Enel and Engie asked FERC to consider this coalition’s comments, with the former suggesting that the coalition favors “highways,” not “driveways,” for renewable interconnections. Enel emphasized that regional transmission planning should build regional projects – highways, to reduce the cost to end-use customers, not the current piecemeal approach of building network upgrades – driveways.